In 2018, a group of the world’s largest crude oil and natural gas producers added more hydrocarbons to their resource base than in any year since at least 2009, according to the annual reports of 116 exploration and production (E&P) companies. During 2018, these companies collectively added a net 10.3 billion barrels of oil equivalent (BOE) to their proved reserves, which totaled 286 billion BOE at the end of the year. Total exploration and development (E&D) costs incurred in 2018 for these companies increased 4% from 2017 levels, but declined 9% from 2017 when calculated as dollars per BOE of proved reserves added. This analysis is based on published financial reports of these 116 companies and does not necessarily represent the financial situation of private companies that do not publish financial reports.
Of the 116 companies, the top 18 held more than 80% of the 286 billion BOE in proved reserves at the end of 2018. Although many of these companies have global operations, some are national oil companies with reserves and operations concentrated in their home countries including Russia, China, and Brazil. Proved reserves change from year to year because of revisions to existing reserves, extensions and discoveries of new resources, purchases and sales of proved reserves, and production. Figure 1 illustrates the 116 companies’ combined proved reserves changes during 2018.
Organic additions to proved reserves—those added through improved recoveryand extensions and discoveries—are linked directly with expenditures in E&D. Proved reserves acquired through purchases and sales represent transfers of assets between companies (including companies outside this group) but are not reflected in E&D expenditures. Revisions to proved reserves can be highly influenced by changes in crude oil and natural gas prices but less directly influenced by E&D investment.
Of the 21.0 billion BOE in organic proved reserves added in 2018 (that is, before accounting for revisions, net reserves purchased, or how much the companies produced), slightly more than half (10.7 billion BOE) came from the United States, while the Russia, Central Asia, and Asia-Pacific region accounted for 4.0 billion BOE (19%). Canada added 2.1 billion BOE (10%) and Latin America added 1.6 billion BOE (8%). Europe and the Middle East and Africa region each added fewer than 1.0 billion BOE, accounting for about 4% of global organic proved reserves additions each (Figure 2).
Global E&D costs incurred increased for the second consecutive year in 2018, increasing 4% to $319 billion. Of this total, 38% ($122 billion) came from the United States, with the Russia, Central Asia, and Asia Pacific region accounting for 26% ($83 billion) and all other regions accounting for less than 10% each. Changes in nominal year-over-year E&D costs incurred varied across regions, increasing by 33% in Europe, 13% in the United States, and 3% in the Middle East and Africa region. Costs incurred declined by 2% both in the Russia, Central Asia, and Asia Pacific region and Latin America, while spending in Canada was essentially flat compared with 2017 (Figure 3).
Because significant cost deflation has occurred in the oil and natural gas industry since 2014, nominal costs incurred in different years may not be directly comparable. Finding costs provide an indicator of the expenditures needed to add a barrel of proved reserves. Because of the disparity between the timing of companies’ capital expenditures and the formal reporting of changes to their proved reserves, standard practice is to average the results over several years.
Analyzed this way, three-year average costs declined on a per BOE basis in 2016–18 compared with both the 2013–15 and the 2010–12 averages (Figure 4). The three-year average E&D costs incurred per BOE of organic proved reserves additions in 2016–18 were lower than their respective 2013–15 and 2010–12 averages in all regions except Latin America, where the 2016–18 average was slightly higher than its 2010–12 average. On an annual basis, the 2018 E&D costs incurred of $15.20 per additional BOE of proved reserves was the lowest since at least 2009.
For further analysis and a list of the companies included in this study, see EIA’s annual Financial Review. Later this year, EIA will issue its annual U.S. crude oil and natural gas proved reserves report which focuses exclusively on proved reserves located in the United States, including all U.S. producers (publicly traded and privately owned companies).
U.S. average regular gasoline and diesel prices decrease
The U.S. average regular gasoline retail price fell 3 cents from the previous week to $2.82 per gallon on May 27, down 14 cents from the same time last year. The Gulf Coast price fell over 4 cents to $2.47 per gallon, the West Coast price fell nearly 4 cents to $3.63 per gallon, the Midwest price fell 3 cents to $2.71 per gallon, the East Coast price fell nearly 3 cents to $2.70 per gallon, and the Rocky Mountain price fell less than one cent, remaining at $2.98 per gallon.
The U.S. average diesel fuel price fell more than 1 cent to $3.15 per gallon on May 27, 14 cents lower than a year ago. The price in each region fell over one cent. The West Coast price fell to $3.78 per gallon, the Rocky Mountain price fell to $3.18 per gallon, the East Coast price fell to $3.16 per gallon, the Midwest price fell to $3.04 per gallon, and the Gulf Coast price fell to $2.89 per gallon.
Propane/propylene inventories decline slightly
U.S. propane/propylene stocks decreased by 0.1 million barrels last week to 65.8 million barrels as of May 24, 2019, 9.8 million barrels (17.5%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast and East Coast inventories decreased by 0.7 million barrels and 0.5 million barrels, respectively. Midwest and Rocky Mountain/West Coast inventories increased by 0.9 million barrels and 0.3 million barrels, respectively. Propylene non-fuel-use inventories represented 8.0% of total propane/propylene inventories.
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Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)
In its January 2020 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that annual U.S. crude oil production will average 11.1 million b/d in 2021, down 0.2 million b/d from 2020 as result of a decline in drilling activity related to low oil prices. A production decline in 2021 would mark the second consecutive year of production declines. Responses to the COVID-19 pandemic led to supply and demand disruptions. EIA expects crude oil production to increase in 2022 by 0.4 million b/d because of increased drilling as prices remain at or near $50 per barrel (b).
The United States set annual natural gas production records in 2018 and 2019, largely because of increased drilling in shale and tight oil formations. The increase in production led to higher volumes of natural gas in storage and a decrease in natural gas prices. In 2020, marketed natural gas production fell by 2% from 2019 levels amid responses to COVID-19. EIA estimates that annual U.S. marketed natural gas production will decline another 2% to average 95.9 billion cubic feet per day (Bcf/d) in 2021. The fall in production will reverse in 2022, when EIA estimates that natural gas production will rise by 2% to 97.6 Bcf/d.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO)
EIA’s forecast for crude oil production is separated into three regions: the Lower 48 states excluding the Federal Gulf of Mexico (GOM) (81% of 2019 crude oil production), the GOM (15%), and Alaska (4%). EIA expects crude oil production in the U.S. Lower 48 states to decline through the first quarter of 2021 and then increase through the rest of the forecast period. As more new wells come online later in 2021, new well production will exceed the decline in legacy wells, driving the increase in overall crude oil production after the first quarter of 2021.
Associated natural gas production from oil-directed wells in the Permian Basin will fall because of lower West Texas Intermediate crude oil prices and reduced drilling activity in the first quarter of 2021. Natural gas production from dry regions such as Appalachia depends on the Henry Hub price. EIA forecasts the Henry Hub price will increase from $2.00 per million British thermal units (MMBtu) in 2020 to $3.01/MMBtu in 2021 and to $3.27/MMBtu in 2022, which will likely prompt an increase in Appalachia's natural gas production. However, natural gas production in Appalachia may be limited by pipeline constraints in 2021 if the Mountain Valley Pipeline (MVP) is delayed. The MVP is scheduled to enter service in late 2021, delivering natural gas from producing regions in northwestern West Virginia to southern Virginia. Natural gas takeaway capacity in the region is quickly filling up since the Atlantic Coast Pipeline was canceled in mid-2020.
Just when it seems that the drama of early December, when the nations of the OPEC+ club squabbled over how to implement and ease their collective supply quotas in 2021, would be repeated, a concession came from the most unlikely quarter of all. Saudi Arabia. OPEC’s swing producer and, especially in recent times, vocal judge, announced that it would voluntarily slash 1 million barrels per day of supply. The move took the oil markets by surprise, sending crude prices soaring but was also very unusual in that it was not even necessary at all.
After a day’s extension to the negotiations, the OPEC+ club had actually already agreed on the path forward for their supply deal through the remainder of Q1 2021. The nations of OPEC+ agreed to ease their overall supply quotas by 75,000 b/d in February and 120,000 b/d in March, bringing the total easing over three months to 695,000 b/d after the UAE spearheaded a revised increase of 500,000 b/d for January. The increases are actually very narrow ones; there were no adjustments for quotas for all OPEC+ members with the exception of Russia and Kazakshtan, who will be able to pump 195,000 additional barrels per day between them. That the increases for February and March were not higher or wider is a reflection of reality: despite Covid-19 vaccinations being rolled out globally, a new and more infectious variant of the coronavirus has started spreading across the world. In fact, there may even be at least of these mutations currently spreading, throwing into question the efficacy of vaccines and triggering new lockdowns. The original schedule of the April 2020 supply deal would have seen OPEC+ adding 2 million b/d of production from January 2021 onwards; the new tranches are far more measured and cognisant of the challenging market.
Then Saudi Arabia decides to shock the market by declaring that the Kingdom would slash an additional million barrels of crude supply above its current quota over February and March post-OPEC+ announcement. Which means that while countries such as Russia, the UAE and Nigeria are working to incrementally increase output, Saudi Arabia is actually subsidising those planned increases by making a massive additional voluntary cut. For a member that threw its weight around last year by unleashing taps to trigger a crude price war with Russia and has been emphasising the need for strict compliant by all members before allowing any collective increases to take place, this is uncharacteristic. Saudi Arabia may be OPEC’s swing producer, but it is certainly not that benevolent. Not least because it is expected to record a massive US$79 billion budget deficit for 2020 as low crude prices eat into the Kingdom’s finances.
So, why is Saudi Arabia doing this?
The last time the Saudis did this was in July 2020, when the severity of the Covid-19 pandemic was at devastating levels and crude prices needed some additional propping up. It succeeded. In January 2021, however, global crude prices are already at the US$50/b level and the market had already cheered the resolution of OPEC+’s positions for the next two months. There was no real urgent need to make voluntary cuts, especially since no other OPEC member would suit especially not the UAE with whom there has been a falling out.
The likeliest reason is leadership. Having failed to convince the rest of the OPEC+ gang to avoid any easing of quotas, Saudi Arabia could be wanting to prove its position by providing a measure of supply security at a time of major price sensitivity due to the Covid-19 resurgence. It will also provide some political ammunition for future negotiations when the group meets in March to decide plans for Q2 2021, turning this magnanimous move into an implicit threat. It could also be the case that Saudi Arabia is planning to pair its voluntary cut with field maintenance works, which would be a nice parallel to the usual refinery maintenance season in Asia where crude demand typically falls by 10-20% as units shut for routine inspections.
It could also be a projection of soft power. After isolating Qatar physically and economically since 2017 over accusations of terrorism support and proximity to Iran, four Middle Eastern states – Saudi Arabia, Bahrain, the UAE and Egypt – have agreed to restore and normalise ties with the peninsula. While acknowledging that a ‘trust deficit’ still remained, the accord avoids the awkward workarounds put in place to deal with the boycott and provides for road for cooperation ahead of a change on guard in the White House. Perhaps Qatar is even thinking of re-joining OPEC? As Saudi Arabia flexes its geopolitical muscle, it does need to pick its battles and re-assert its position. Showcasing political leadership as the world’s crude swing producer is as good a way of demonstrating that as any, even if it is planning to claim dues in the future.
It worked. It has successfully changed the market narrative from inter-OPEC+ squabbling to a more stabilised crude market. Saudi Arabia’s patience in prolonging this benevolent role is unknown, but for now, it has achieved what it wanted to achieve: return visibility to the Kingdom as the global oil leader, and having crude oil prices rise by nearly 10%.